Not applicable.
Not applicable.
This invention relates generally to a method and apparatus for performing fluid analysis downhole in a well, and more particularly to a system for in situ determination of type and condition of formation fluids in a wellbore and for collecting downhole formation fluid samples under the original formation conditions. Still more particularly, the present invention relates to a downhole tool that uses acoustic scattering of a signal to provide qualitative measurements of the degree and nature of particulate inclusions present in the fluid sample.
In the oil and gas industry, wireline tools perform a variety of functions, including sealing different parts of the well, electromagnetically or acoustically measuring the formation, or perforating the well casing so as to allow the entry of well fluids through the perforation. These wireline tools, so-called because they are lowered into the well on a long cable or xe2x80x9cwire,xe2x80x9d also include formation testing tools that monitor formation pressures, obtain formation fluid samples and obtain other measurements that are used for predicting reservoir performance. Wireline formation testing tools typically include an elongated body with a packer or sealing element that is used to seal the zone of interest in the wellbore, so that formation fluid samples from that zone can be received into storage chambers in the tool or passed through a downhole measuring device.
Various types of drilling fluids are used to facilitate the drilling process and to maintain a desired hydrostatic pressure in the wellbore. These drilling fluids penetrate into or xe2x80x9cinvadexe2x80x9d the formation to varying radial depths (referred to generally as the invaded zones) depending upon the type of formation and the type of drilling fluid. In addition, as the drilling fluid invades a stratum or layer in the formation, solids that were present in the drilling fluid are filtered out by the formation, forming a xe2x80x9cmud cake.xe2x80x9d The liquid portion of the invading drilling fluid, known as xe2x80x9cfiltrate,xe2x80x9d thus often invades much more deeply into the formation than does the solid portion.
When it is desired to sample the formation fluid, it is necessary to ensure that both the filter cake and the filtrate have been removed from the sampled region, otherwise the sample will be contaminated with some portion of the drilling fluid. Hence, the fluid stream collected by the formation testing tools must be analyzed to determine when the formation fluid being withdrawn is substantially free of mud and mud filtrates.
For example, resistivity measurements have been applied to distinguish oil (or gas) and water and determine the proportion of each fluid phase. Optical techniques have been utilized to identify the type of formation fluid, i.e. to differentiate between oil, water and gas present in the formation fluid. Optical reflection technique is utilized to detect gas bubbles at the optical window-fluid interface. Visible and near-infrared absorption spectrometer has also been used to differentiate between crude oils, water, and drilling mud.
These prior art systems are not entirely satisfactory, however, inasmuch as interpretation of their results is difficult and often inaccurate. Systems using fluid resistivity to determine oil/water are affected by the flow dynamics and fluid salinity, which are not always available. Since resistivity measured is that of the continuous phase of the fluid in the flowline, the resistivity measurement works well for water-hydrocarbon mixtures with water as the continuous phase, but fails for mixtures with hydrocarbon as the continuous phase. A flow of alternating slugs of hydrocarbon and water produces noisy resistivity recording. The difficulty in interpreting flowline resistivity is even greater when gas is present. The resistivity measurement can not distinguish between gas and oil.
In addition, the windows of optical devices may become coated with hydrocarbons (asphaltene, paraffin) that may distort their results. The devices also suffer from small depth of penetration for opaque fluids. This reduces their accuracy in some applications. Furthermore, optical devices can detect gas bubbles located only at the surface of optical window, and provide no estimate of fluid compressibility.
For these reasons, ultrasonic signaling has been considered for fluid analysis. Like the systems described above, however, conventional acoustic fluid analysis techniques are not entirely satisfactory. Specifically, the piezoelectric devices that are suitable transducers for use in the downhole environment tend to exhibit significant response drift when subjected to large changes in temperature or pressure. Hence, conventional acoustic fluid analysis systems require frequent calibration of the instrument, particularly when temperature or pressure is highly variable. None of the prior art systems provides an effective means for using ultrasound scattering to detect and analyze gas bubbles, or fine particles, applications primarily associated with reservoir fluid sampling and analyzing.
Thus, it is an objective of this invention to provide for a formation fluid analysis system that is relatively simple, more robust than the current state-of-the-art systems and relatively accurate in differentiating between the various types of particulate and fluids to ensure that substantially uncontaminated formation fluid samples are collected. The desired system would avoid the need for calibration of the instrument over wide temperature and pressure ranges and would detect and analyze gas bubbles, fine particles, and liquid droplets in fluid samples.
The present invention addresses the above-noted deficiencies and provides a relatively simple and robust system for analyzing one or more formation fluid samples under original formation conditions using a novel acoustic cell. The present technique includes a fluid analysis method that allows identification of various suspended particulates and liquids in downhole reservoir fluids, based upon compensated acoustic scattering measurement. The suspended particulates can be solid particles, liquid droplets of a liquid that is immiscible in a continuous liquid, or gas bubbles. The continuous liquid medium can be oil, water, or any oil-based or water-based mixture. The longitudinal acoustic impedance (longitudinal speed of soundxc3x97density) of the particulate should be different from that of the carrier liquid medium. The method comprises transmitting tone-burst waves into the fluid and measuring the amplitude of signals scattered by the particulates in the fluids and received at a plurality of azimuthally positioned receivers.
The present apparatus is robust enough for downhole use, yet avoids many of the difficulties that are inherent in previous systems. For example, the present system produces results that are less difficult to characterize than resistivity measurements when flow regime or fluid salinity is unknown, and uses a system that is largely unaffected by deposition of paraffin and asphaltene, in contrast to an optical system. Unlike previously known acoustical systems, the present system uses acoustical equipment that does not require temperature dependent calibration.
In one preferred embodiment, the present fluid analysis apparatus includes two acoustic transmitting transducers positioned opposite to each other and two receiving transducers positioned at different angles on the circumference of a cylindrical conduit. The two transmitters intermittently emit tone-burst signals at a predetermined repetition time interval. The two receivers receive scattered signals from the sample. The power amplitudes measured from the two receivers as result of emission from the first transmitter and the amplitudes as result of emission from the second transmitter are used to calculate a dimensionless parameter related to the density and compressibility of the particulate and fluid medium. By comparing the calculated parameter with known values in a database, the sample can be characterized. By tracking the value of the calculated parameter over time, changes in the nature of a fluid stream can be detected.
In a second embodiment, a device comprising one transmitter and at least three receivers is disclosed. The scattering power amplitudes from the receivers normalized by the amplitude from a reference receiver as function of scattering angles are used to identify and monitor the fluid sample.